Our Company
We are an oil and gas exploration and development company. We currently own over 865,893 gross (approximately 293,843 net) mineral and lease acres in New Mexico and Texas. Approximately 25,000 of these net acres exist within the Permian Basin. A significant majority of our acreage consists of either owned mineral rights or leases held by production. The majority of our acreage interests consists of non-operated working interests except for certain core San Andres properties which we operate.
Current development of our acreage is focused on our prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, Occidental, Oxy USA and, Mewbourne; all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions.
History
We were originally formed on October 25, 2005 under the name “Language Enterprises Corp.” We subsequently changed our name to Doral Energy Corp. On July 29, 2008, we acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of our acquisition of the Eddy County Properties, we changed our business focus to the acquisition, exploration, operation and development of oil and gas projects, and we ceased being a “shell company.” On August 4, 2008, we filed our Form 8-K that included the information that would be required if we were filing a general form for registration of securities on Form 10 as a smaller reporting company.
Effective January 3, 2011, we completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to the Pure Merger Agreement among our company, Doral Sub, Pure L.P. and Pure Sub, a wholly owned subsidiary of Pure L.P. Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of our common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of our common stock to the partners of Pure L.P. so that Pure L.P. is no longer a shareholder of our company.
Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into our company, with our company continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into our company, we changed our name to “Cross Border Resources, Inc.”
On January 28, 2013, Red Mountain Resources, Inc. closed the acquisition of 5,091,210 shares of our common, bringing its total ownership to approximately 78% of the outstanding common stock of the company. Prior to the acquisition, Red Mountain Resources, Inc. owned 47% of our outstanding common stock. As of the date of this report, Red Mountain Resources, Inc. owns approximately 81% of our outstanding common stock. As a result of that transaction, our results are consolidated in Red Mountain Resources, Inc.’s financial statements.
First Quarter 2013 Operational Update
In the first half of fiscal 2013 we completed 15 gross wells (1.40 net). These included 6 horizontal Bone Spring wells (0.91 net), 2 horizontal Yeso wells (0.11 net), 6 vertical Glorieta-Yeso wells (0.32 net), and 1 vertical Queen-Grayburg-San Andres well (0.06 net). On June 30, 2013, there were 2 wells (0.06 net) drilled and awaiting completions. Both are vertical Glorieta-Yeso wells. Also during this period, we received approval to begin remediation work and field redevelopment in the Tom Tom area. The first work was performed in May. At the end of the quarter, 3 workovers were completed, each showing positive results.
Planned Operations
We plan to spend between $8 million and $12 million during fiscal 2013 to drill and complete wells, re-enter and complete wells, or improve infrastructure. Our main area of focus is the Tom Tom/Tomahawk Prospect, where we will work on the field alongside the execution of our remediation plan. For fiscal 2013, this includes the re-entry of 14 gross wells (11.7 net), drilling of 6 gross wells (5.2 net), and the improvement of field infrastructure. We will also spend capital in several non-operated prospect areas. Currently, we are committed to participating in the drilling of 3 gross wells (0.3 net), and we expect to receive addition well proposals before the end of fiscal 2013. We expect to finance these activities with cashflow generated from operations and availability under our line of credit with Independent Bank
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Summary of Significant Accounting Policies” to our consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.
Oil and Gas Properties
We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at December 31, 2012 or 2011. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2012, we had capitalized no interest costs because our exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of natural gas to one Boe. The ratio of six Mcf of natural gas to one Boe is based on energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.
It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance
of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.
On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of Long-Lived Assets
We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
In the second quarter of 2012, the Company determined to sale its Wolfberry assets located in Texas. As a result of that decision, management conducted an impairment evaluation of those assets which resulted in a non cash impairment charge of approximately $1,776,000.
Additionally, during the fourth quarter of 2012, management conducted an impairment evaluation of its proved and unproved oil and natural gas properties. As a result of the evaluation, management recorded a non cash impairment charge of approximately $1,208,000, primarily related to a decline in the value of proved reserves.
Recent Accounting Pronouncements
In May 2011, the FASB issued an accounting pronouncement related to fair value measurement (FASB ASC Topic 820), which amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The amendments generally represent clarification of FASB ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our consolidated financial statements.
In December 2011, the Financial Accounting Standards Board (“FASB”) issued new standards that require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The new standards are effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of the new standards and assessing the impact, if any, it may have on our financial position and results of operations.
In January 2010, the FASB issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and Level 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010.
Results of Operations
Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012
The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the three months ended June 30, 2013 and 2012.
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Three Months Ended June 30,
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|
|
|
|
|
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(dollars in thousands, except per unit prices)
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|
|
|
Revenue
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|
|
|
|
|
|
Oil and natural gas sales
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|
$
|
3,461,249
|
|
|
$
|
4,147,645
|
|
|
|
|
|
|
|
|
|
|
Net Production sold
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|
|
|
|
|
|
|
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Oil (Bbl)
|
|
|
35,601
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|
|
|
42,105
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|
Natural gas (Mcf)
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|
|
56,550
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|
|
|
59,121
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|
Total (Boe)
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|
|
45,026
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|
|
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51,959
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Total (Boe/d) (1)
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|
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495
|
|
|
|
571
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|
|
|
|
|
|
|
|
|
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Average sales prices
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|
|
|
|
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Oil ($/Bbl)
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$
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89.85
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|
|
$
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88.87
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Natural gas ($/Mcf)
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|
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5.42
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|
|
|
4.78
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Total average price ($/Boe)
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$
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77.97
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|
|
$
|
74.65
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|
|
|
|
|
|
|
|
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Costs and expenses (per Boe)
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|
|
|
|
|
|
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Operating costs
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$
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19.80
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|
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$
|
11.67
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Production taxes
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|
|
5.65
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|
|
|
7.09
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Depreciation, depletion, and amortization
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|
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37.29
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|
|
|
53.27
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|
Accretion of discount on asset retirement obligation
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|
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0.82
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|
|
|
0.56
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General and administrative expense
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|
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5.85
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|
|
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30.06
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_________________
(1) Boe/d is calculated based on actual calendar days during the period.
Three months Revenues and Sales Volumes
Oil and Natural Gas Sales Volumes.
During the three months ended June 30, 2013, we had total sales volumes of 45,026 Boe, compared to total sales volumes of 51,959 Boe during the three months ended June 30, 2012. This decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately 3,200 Boe to sales volumes during the three months ended June 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the three months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and gas wells. This natural production decline was offset by the drilling of new wells.
Oil and Natural Gas Sales.
During the three months ended June 30, 2013, we had oil and natural gas sales of $3.5 million, as compared to $4.1 million during the three months ended June 30, 2012 the decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately $230,000 to revenue in the three months ended June 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the three months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and gas wells. This natural production decline was offset by the drilling of new wells.
Costs and Expenses
Operating Costs.
During the quarter ended June 30, 2013, we incurred operating costs of $0.9 million, as compared to $0.2 million during the quarter ended June 30, 2012. The increase in operating costs is attributable to higher costs associated with workover activity at our Tom Tom field.
Production Taxes
. Production taxes were $0.3 million for the quarter ended June 30, 2013, as compared to $0.4 million for the quarter ended June 30, 2012.
Depreciation, Depletion, Amortization and Impairment.
For the quarter ended June 30, 2013, depreciation, depletion, amortization, and impairment was $1.7 million, as compared to $2.8 million for the quarter ended June 30, 2012. The decrease in depreciation, depletion, amortization, and impairment was attributable to an impairment charge of $1.8 million related to our Wolfberry assets during the quarter ended June 30, 2012.
General and Administrative Expense.
General and administrative expense was $0.3 million for the quarter ended June 30, 2012, as compared to $1.6 million for the quarter ended June 30, 2012. The decrease was a result of personnel costs, change of control expenses, and professional fees being lower in the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.
Other Expense / Income.
Other expense was $0.05 million for the quarter ended June 30, 2013, as compared to income of $1.3 million for the quarter ended June 30, 2012. The decrease in income is due to non-cash losses on derivatives contracts.
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the six months ended June 30, 2013 and 2012.
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Six Months Ended June 30,
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(dollars in thousands, except per unit prices)
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|
|
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Revenue
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|
|
|
|
|
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Oil and natural gas sales
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|
$
|
6,794,047
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|
|
$
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7,721,391
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|
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|
|
|
|
|
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|
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Net Production sold
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|
|
|
|
|
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|
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Oil (Bbl)
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|
|
61,923
|
|
|
|
74,521
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Natural gas (Mcf)
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|
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133,618
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|
|
|
113,491
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Total (Boe)
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|
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84,192
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|
|
|
96,436
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|
Total (Boe/d) (1)
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|
|
465
|
|
|
|
487
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|
|
|
|
|
|
|
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Average sales prices
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
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|
$
|
86.40
|
|
|
$
|
93.04
|
|
Natural gas ($/Mcf)
|
|
|
5.41
|
|
|
|
5.30
|
|
Total average price ($/Boe)
|
|
$
|
80.70
|
|
|
$
|
80.07
|
|
|
|
|
|
|
|
|
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Costs and expenses (per Boe)
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|
|
|
|
|
|
|
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Operating costs
|
|
$
|
15.91
|
|
|
$
|
13.42
|
|
Production taxes
|
|
|
4.61
|
|
|
|
5.66
|
|
Depreciation, depletion, and amortization
|
|
|
33.19
|
|
|
|
34.34
|
|
Accretion of discount on asset retirement obligation
|
|
|
0.85
|
|
|
|
0.36
|
|
General and administrative expense
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|
|
7.08
|
|
|
|
23.16
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|
_______________
(1) Boe/d is calculated based on actual calendar days during the period.
Six months Revenues and Sales Volumes
Oil and Natural Gas Sales Volumes.
During the six months ended June 30, 2013, we had total sales volumes of 84,192 Boe, compared to total sales volumes of 96,436 Boe during the six months ended June 30, 2012. This decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately 5,100 Boe to sales volumes during the six months ended June 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the six months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and gas wells. This natural production decline was offset by the drilling of new wells.
Oil and Natural Gas Sales.
During the six months ended June 30, 2013, we had oil and natural gas sales of $6.8 million, as compared to $7.7 million during the six months ended June 30, 2012 the decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately $460,000 to revenue in the six months ended June 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the six months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and gas wells. This natural production decline was offset by the drilling of new wells.
Costs and Expenses
Operating Costs.
During the six months ended June 30, 2013, we incurred operating costs of $1.4 million, as compared to $1.0 million during the six months ended June 30, 2012. The increase in operating costs is attributable to higher costs associated with workover activity at our Tom Tom field.
Production Taxes
. Production taxes were $0.4 million for the six months ended June 30, 2013, as compared to $0.5 million for the quarter ended June 30, 2012, which is attributable to higher production in the six months ended June 30, 2012.
Depreciation, Depletion, Amortization and Impairment.
For the six months ended June 30, 2013, depreciation, depletion, amortization, and impairment was $2.8 million, as compared to $3.3 million for the quarter ended June 30, 2012. The decrease in depreciation, depletion, amortization, and impairment was attributable to an impairment charge of $1.8 million related to our Wolfberry assets during the six months ended June 30, 2012, which did not recur in the six months ended June 30, 2013.
General and Administrative Expense.
General and administrative expense was $0.6 million for the six months ended June 30, 2013, as compared to $2.2 million for the six months ended June 30, 2012. The decrease was a result of personnel costs, change of control expenses, and professional fees being lower in the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.
Other Expense / Income.
Other expense was $0.5 million for the six months ended June 30, 2013, as compared to income of $0.5 million for the six ended June 30, 2012.
Liquidity and Capital Resources
General
Our primary sources of liquidity are cash flow from operations and borrowings under our line of credit. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our line of credit and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control.
Capital Expenditures
Most of our capital expenditures are for the exploration, development, and production of oil and natural gas reserves. For the six months ended June 30, 2013, we had capital expenditures of approximately $6.9 million for the development of oil and natural gas properties. We anticipate capital expenditures of between 8 million and 12 million for 2013. See “Planned Operations” for more information about our planned capital expenditures.
Liquidity
At June 30 2013, we had approximately $73,000 in cash and cash equivalents and $12.2 million outstanding under our line of credit with Independent Bank. At June 30, 2013, we had a working capital deficit of $1.3 million compared to a working capital deficit of $3.3 million at December 31, 2012.
On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement with Independent Bank. Our initial draw on the line of credit was $8.9 million which was primarily used to pay off the Texas Capital Bank line of credit principal and accrued interest. On February 28, 2013, we drew $2,000,000 and on May 24, 2013, we drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program. As of June 30, 2013, the Credit Agreement balance was $12,200,000, leaving no availability.
In February 2013, we settled certain creditors liability for $633,975 in cash and by arranging for our largest shareholder, Red Mountain Resources, Inc., to issue the creditors an aggregate of 745,854 shares of its common stock. Further, the holder of the subordinated unsecured debt elected to convert the entire principal and accrued interest balance of the notes into 611,630 shares of our common stock.
Cash Flows
Net cash provided by operating activities was $5.4 million for the six months ended June 30, 2013, compared to net cash provided by operating activities of $4.3 million for the six months ended June 30, 2012. The increase in net cash provided by operating activities was primarily due to a $2.0 million profit and $2.8 million of non-cash depreciation, depletion, amortization and impairment, offset by ($0.8 million) of accounts receivable.
Net cash used in investing activities decreased to $6.8 million for the six months ended June 30, 2013 from $7.9 million for the six months ended June 30, 2012 due to a decrease in capital expenditures..
During the six months ended June 30, 2013, net cash provided by financing activities was $1.3 million, as compared to $3.5 million during the six months ended June 30, 2012. Net cash provided by financing activities during the six months ended June 30, 2013 was primarily comprised of $12.2 million drawn under our Independent Bank line of credit, offset by repayments of our Texas Capital Bank line of credit of $8.75 million, repayments of notes of $0.8 million, and repayments to creditors of $1.3 million.
Indebtedness
Notes Payable- Green Shoe
In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Green Shoe Investments Ltd. (“Green Shoe”) in the principal amount of $487,000 at an interest rate of 5.0%
On April 26, 2011, the Company entered into a Loan Agreement with Green Shoe, and the Company executed and delivered a Promissory Note to Green Shoe in connection therewith. The amount of the Promissory Note and the loan from Green Shoe (the “Green Shoe Loan”) was $550,936 and the purpose of the Green Shoe Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Green Shoe including without limitation the following: (i) loan dated May 9, 2008 in the principal amount of $100,000, (ii) loan dated May 23, 2008 in the principal amount of $150,000, (iii) loan dated July 18, 2008 in the principal amount of $50,000, (iv) loan dated February 24, 2009 in the principal amount of $100,000, and (v) loan dated April 29, 2009 in the principal amount of $87,000 plus accrued interest of $63,936. The Green Shoe Loan is unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Green Shoe was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 was $367,309.
The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Green Shoe Investments. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $367,309 and an accrued interest balance of $62,924.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock. Accordingly, at June 30, 2013, the balance of the note was zero.
Notes Payable- Little Bay
In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Little Bay Consulting SA (“Little Bay”) in the principal amount of $520,000 at an interest rate of 5%.
On April 26, 2011, the Company entered into a Loan Agreement with Little Bay, and the Company executed and delivered a Promissory Note to Little Bay in connection therewith. The amount of the Promissory Note and the loan from Little Bay (the “Little Bay Loan”) was $595,423 and the purpose of the Little Bay Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Little Bay including without limitation the following: (i) loan dated March 7, 2008 in the original principal amount of $220,000, (ii) loan dated July 18, 2008 in the original principal amount of $100,000, and (iii) loan dated October 3, 2008 in the principal amount of $200,000 plus accrued interest of $75,423. The Little Bay Loan is unsecured.
Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 is $396,969.
The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Little Bay Consulting, S.A. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $396,969 and an accrued interest balance of $68,005.
On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $396,969 and accrued interest balance of $79,555 into 317,683 shares of the Company’s common stock. Accordingly, at June 30, 2013, the balance of the note was zero.
Line of Credit
As of December 31, 2011, the borrowing base on the Texas Capital Bank (“TCB”) line of credit was $4,500,000. Effective March 1, 2012, the borrowing base was increased to $9,500,000. The interest rate was calculated at the greater of the adjusted base rate or 4%. The line of credit was collateralized by producing wells and was to mature on January 14, 2014. As the result of the sale of certain interests in oil and gas properties, effective August 1, 2012, the borrowing base was reduced by $750,000 and that amount was repaid to TCB out of the sale proceeds.
On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with Red Mountain Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank, as Lender. Red Mountain owns approximately 85% of the outstanding common stock of Cross Border and Black Rock and RMR Operating are wholly owned subsidiaries of Red Mountain. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used a portion of that draw to fully pay down the TCB line of credit. On February 28, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay outstanding accounts payable related to our drilling program. As of June 30, 2013, the Credit Agreement balance was $12,200,000, leaving $200,000 available.
Off-Balance Sheet Arrangements
As of June 30, 2013, we did not have any off-balance sheet arrangements as defined by Regulation S-K.
Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” believe,” “expect,” anticipate,” “plan,” “estimate,” “target,” “project,” or “intend” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.
Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:
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our ability to raise additional capital to fund future capital expenditures;
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our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;
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declines or volatility in the prices we receive for our oil and natural gas;
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general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
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risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;
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uncertainties associated with estimates of proved oil and natural gas reserves;
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the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
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risks and liabilities associated with acquired companies and properties;
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risks related to integration of acquired companies and properties;
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potential defects in title to our properties;
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cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;
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geological concentration of our reserves;
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environmental or other governmental regulations, including legislation of hydraulic fracture stimulation;
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our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
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exploration and development risks;
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management’s ability to execute our plans to meet our goals;
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our ability to retain key members of our management team;
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actions or inactions of third-party operators of our properties;
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costs and liabilities associated with environmental, health and safety laws;
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our ability to find and retain highly skilled personnel;
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operating hazards attendant to the oil and natural gas business;
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competition in the oil and natural gas industry; and
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the other factors discussed under Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.
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Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.